Note: Descriptions are shown in the official language in which they were submitted.
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MEASUREMENT-WHILE-DRILLING ASSEMBLY USING REAL-
TIME TOOLFACE ORIENTED MEASUREMENTS
FIELD OF THE INVENTION
[0001] This invention relates generally to assemblies for making toolface
oriented measurements within a borehole and processing of such measurements
to determine parameters of interest of materials around the borehole. The
invention is described in the context of measurement-while-drilling
applications
for obtaining formation properties but the principles of analysis are equally
applicable to measurements made with a wireline conveyed instrument.
BACKGROUND OF THE INVENTION
[0002] To obtain hydrocarbons such as oil and gas, wellbores (also called the
boreholes) are drilled by rotating a drill bit attached at the end of a
drilling
assembly generally called the "bottom hole assembly" or the "drilling
assembly." A large portion of the current drilling activity involves drilling
highly deviated or substantially horizontal wellbores to increase the
hydrocarbon production and/or to withdraw additional hydrocarbons from the
earth's formations. The wellbore path of such wells is carefully planned
before
drilling such wellbores using seismic maps of the earth's subsurface and well
data from previously drilled wellbores in the associated oil fields. Due to
the
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very high cost of drilling such wellbores and the need precisely to place such
welibores in the reservoirs, it is essential continually to determine the
position
and direction of the drilling assembly and thus the drill bit during drilling
of the
wellbores. Such information is used, among other things, to monitor and adjust
the drilling direction of the wellbores.
[0003] In drilling assemblies used until recently, the directional package
cornm.only includes a set of accelerometers and a set of magnetometers, which
respectively measure the earth's gravity and magnetic field. The drilling
assembly is held stationary during the taking of the measurements from the
accelerometers and the magnetometers. The toolface and the inclination angle
are determined from the accelerometer measurements. The azimuth is then
determined from the magnetometer measurements in conjunction with the tool
face and inclination angle.
[0004] The earth's magnetic field varies from day to day, which causes
corresponding changes in the magnetic azimuth. The varying magnetic azimuth
compromises the accuracy of the position measurements when magnetometers
are used. Additionally, it is not feasible to measure the earth's magnetic
field in
the presence of ferrous materials, such as casing and drill pipe. Gyroscopes
measure the rate of the earth's rotation, which does not change with time nor
are
the gyroscopes adversely affected by the presence of ferrous materials. Thus,
in
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the presence of ferrous materials the gyroscopic measurements can provide
more accurate azimuth measurements than the magnetometer measurements.
U.S. Patent 6,347,282 to Estes et al having the same assignee as the present
application and the contents of which are fully incorporated herein by
reference,
discloses a measurement-while-drilling (MWD) downhole assembly for use in
drilling boreholes that utilizes gyroscopes, magnetometers and accelerometers
for detennining the borehole inclination and azimuth during the drilling of
the
borehole. The downhole assembly includes at least one gyroscope that is
rotatably mounted in a tool housing to provide signals relating to the earth's
rotation. A device in the tool can rotate the gyroscope and other sensors on
the
tool at any desired angle. This ability to rotate the sensors is important in
determining bias in the sensors and eliminating the effects of the bias.
[0005] U.S. Patent 5091644 to Minette having the same assignee as the present
application teaches a method for analyzing data from a measurement-while-
drilling (MWD) gamina ray density logging tool which compensates for
rotations of the logging tool (along with the rest of the drillstring) during
measurement periods. In accordance with the method disclosed therein, the
received signal is broken down into a plurality of sections. In a preferred
enlbodiment, the Minette invention calls for the breaking of the signal from
the
forination into four different sections: top, bottom, right, left. As the tool
rotates, it passes through these four quadrants. Each time it passes a
boundary,
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a counter is incremented, pointing to the next quadrant. This allows for
dividing the data into four spectra for each detector. Each of these four
spectra
will be obtained for 1/4th of the total acquisition time assuming constant
rotational speed.
[0006] U.S. Patent 6307199 to Edwards et al teaches the use of a density
gamma ray logging device in which data from different "azimuthal" sectors are
combined to give an interpretation of formation dip. The primary emphasis in
both the Minette and Edwards patent is to correct the density measurements for
the effects of standoff; the sensors themselves are not specifically designed
for
"azimuthal" sensitivity. US Patent 6215120 to Gadeken et al. discloses the use
of "azimuthally" focused gamma ray sensors on a logging tool for detecting
"azimuthal" variations in the gamma ray emission from earth formations.
[0007] Other types of images have been obtained in the prior art using sensors
on a rotating bottom hole assembly (BHA). For example, US Patent 5,200,705
to Clark et al. discusses resistivity measurements made by a galvanic
resistivity
sensor on a stabilizer blade. U.S. Patent 6,173,793 to Thompson et al., having
the same assignee as the present invention and the contents of which are fully
incorporated herein by reference, teaches the use of pad mounted sensors on a
slowly rotating sleeve for obtaining azimuthal resistivity images of the
borehole
wall. Resistivity images can, for the purpose of the present invention, be
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considered to be similar to images obtained with a nuclear logging tool,
albeit
with a much higher resolution. Resistivity mesurements do not suffer from the
statistical variability associated with nuclear logging tools and can hence
make
virtually instantaneous measurements yielding images with a much higher
resolution than can nuclear measurements.
[0008] We digress briefly on a matter of terminology. In surveying, the term
"azimuth" usually refers to an angle in a horizontal plane, usually measured
from north: when referenced to magnetic north, it may be called magnetic
azimuth and when referenced to true north, it is usually simply termed
azimuth.
It would be clear based on this definition that all measurements made in a
highly deviated borehole or a horizontal borehole would be made with
substantially the same azimuth. Accordingly, in the present application, we
use
the more accurate term "tool face angle" to define a relative orientation in a
plane orthogonal to the borehole axis. With this definition, the Minette,
Edwards and Gadeken patents are really making measurements over a variety of
tool face angles.
[0009] Common to the Minette, Edwards and Gadeken patents is the use of a
controller that keeps track of the rotating sensor assembly and controls the
acquisition of data based on sector boundaries in the tool face angle. While
this
may not be difficult to do for the case of a single directionally sensitive
sensor,
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the problem becomes much more complicated ,vhen a plurality of different types
of
sensors are conveyed as part of a bottom hole assembly. It is difficult, if
not impossible,
for a single controller to keep traclc of a plurality of sensor assemblies
during rotation of
the downhole assembly and control the operation of a plurality of assemblies.
A source of
error is the nonLu-iiform rotation speed of the drilistring. Another source of
error is the
titne delay inherent in the electronics. Measurements may be made
simultaneously by the
formation sensor and the orientation sensors, but there is a time delay
between the time the
n.leasurements are made with the two types of sensors and the time at whicli
they are
processed. The interaction between the two sources of error, i. e.,
noniiniforni rotation and
time delay, can be fairly complex. The problem of nonuniform rotation is
partially
addressed in copending U.S. Patent 7,000,700 of Cairns et. al. having the same
assignee.
IIowever. addressing the non-uniform rotation by itself gives only a partial
solution. In
addition, there is the problein of bias in the orielitation sensor
measurements. Generally,
magnetometers are preferred as orientation sensors over gyroscopes, but
magnetometers
are susceptible to errors causes by metallic drill collars, casing, and
accunzulated debris.
There is a need for a method of determining accurate orientation values using
measurements made by a an orientation sensor on a MWD logging tool. It would
be
desirable to have an apparatus and a method that efficiently controls data
acquisition and
possibly processing with a plurality
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of rotating sensors in a downhole device. The present invention satisfies this
need.
SUMMARY OF THE INVENTION
[0010] One embodiment of the present invention includes a rotatable downhole
assembly adapted for conveying in a borehole and determining a parameter of
interest of a medium near to the borehole. The downhole assembly includes a
first sensing device such as a gyroscope, a magnetometer, and/or an
accelerometer, for providing a measurement indicative of the toolface angle of
the downhole assembly, and an associated processor. The downhole assembly
also includes a directional formation evaluation device for providing
measurements indicative of a parameter of interest of the medium. The
directional evaluation device is associated with a second processor. The first
processor provides processed data about the toolface orientation to a common
bus operatively connected to the first processor and the second processor. In
one embodiment of the invention, a gyroscope is used to provide information
about the location of the assembly. The assembly may be conveyed on a
drillstring, coiled tubing or on a wireline.
[0011] In one embodiment of the invention, the directional device is a
formation evaluation device. One or more garnma ray sensors may be used.
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'1'lle fornlation evaluation device may be operated independently of the
orientation sensor.
With this arrangement, a plurality of formation evaluation sensors may be
used.
Subsediient processing relates the measurements of the formation evaluation
sensors to
toolface angle and provides information about downhole parameters.
100121 Apparent and relative dip angles of the borehole with respect to an
interface in the
earth formations niay be determined. T'he rate of penetration needed for this
determination
niay be obtained using downhole accelerometers, a pair of formation evaluation
sensors at
a known spacing, or telemetered from the surface. These detennined dip angles
may be
used for controlling the drilling direction.
[0012a] Accordingly, in one aspect of the present invention there is provided
an apparatus
for use on a bottom hole assembly (BHA) for conveying in a borehole in an
earth
formation, the apparatus comprising:
an orientation sensor making measurements indicative of a toolface angle of
said
BHA during rotation of the BHA, the orientation sensor associated with a first
processor
and;
at least one directionally sensitive formation evaluation sensor for making
measurements of a parameter of interest of said earth formation during said
continued
rotation, the directionally sensitive formation evaluation sensor associated
with a second
processor, said first and second processors being on a common bus;
wherein a said processor determines, in use, from said measurements of said
parameter of interest and said orientation sensor measurements an apparent dip
angle
between an axis of said borehole and an interface in said earth formation,
wherein said
BHA has a non-uniform rate of rotation, in use.
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[0012b] According to another aspect of the present invention there is provided
a method of
determining a dip characteristic of an earth formation, the method comprising:
conveying a bottom hole assembly (BHA) into a borehole in an earth formation;
using an orientation sensor on said BHA for making measurements indicative of
a
toolface angle of said BHA during rotation of the BHA, wherein the orientation
sensor is
associated with a first processor;
using at least one directionally sensitive formation evaluation sensor on said
BHA
for making measurements of a parameter of interest of said earth formation
during said
continued rotation, wherein the at least one directionally sensitive formation
evaluation
sensor is associated with a second processor, the first processor and the
second processor
coupled to a common bus; and
determining from said measurements of said parameter of interest aiid said
orientation sensor measurements said dip characteristic of said earth
formation, said
determination correcting for a non-uniform rate of rotation of said BHA.
BRIEF DESCR[PTION OF THE DRAWINGS
100131 For detailed understanding of the present invention, references should
be made to
the following detailed description of the present invention, taken in
conjunction with the
accompanying drawings, in which like elements have been given like numerals,
vvherein:
Figure 1(prior art) sliows a schematic diagram of a drilling system that
includes the
apparatus of the current invention in a ni easuretnent-while-drilling
embodi.tnent;
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Figure 2a, 2b (prior art) shows a schematic diagram of a portion of the
bottomhole assembly with a set of gyroscopes and a corresponding set of
accelerometers according to a preferred embodiment of the present invention;
Figure 3 shows an orientation sensor assembly and a dual detector gamma ray
sensor;
Figure 4 shows the tool face angle as a function of time;
Figure 5 shows an azimuthal display of time ticks;
Figure 6 illustrates the azimuthal resolution of an exemplary gamma ray
directional logging tool;
Figure 7 illustrates the configuration of the apparatus of the present
invention
for determining relative angle with respect to a bed boundary;
Figure 8 illustrates the directional measurements made by the apparatus as
shown in Fig. 7; and
Figure 9 illustrates a flow chart of the method used for characterizing the
toolface-angle dependent data in a series expansion.
Figure 10 shows an example of processing of the data using the method of the
present invention.
Figure 11 shows a block diagram of an apparatus for making nuclear
measurements as a function of azimuth;
Fig. 12 shows a illustrating standoff and orientation sensors in a cross
sectional
view;
Fig. 13 shows measurements that would be made by two orthogonal
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maunetonleters as a ftinction of tool rotation in a vertical borehole;
Fig. 14 shows the effect of rotation speed on nuclear measureinents made with
an
exemplary sensor assemblv;
Fig. 15 shows siniulated results of error in azimuth determination as a
function of rotation
speed;
Figs. 16a and 16b show the outputs of two orthogonal magnetometers on a
rotating
bottom hole assembly, and an error in the magnetometer measurements;
Fig. 17 shows a flow chart of an embodiment of the invention for correcting
for errors
resulting fronl use of the magnetometer measurements;
Fig. 18 shows corrected nleasurements corresponding to Fig. 14 using the
rnethod of the
present invention;
Fig. 19 shows an example of residual errors in use of the magnetometer outputs
using the
method of the present invention;
Fig. 20 shows an arrangement of pad mounted resistivity sensor;
Fig. 21 shows unwrapped resistivity measurements as a function of time.
Fig. 22 shows unwrapped resisitivity measurements as a function of depth.
Fig. 23 is a schematic illustration of the appearance of a bed with irregular
rotation of the
drillstrinn
Fig. 24 is a schematic illustration of an image having a number of boundaries
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with possible stick-slip.
Figs 25a, 25b illustrate the use of the present invention for reservoir
navigation.
DETAILED DESCRIPTION OF THE INVENTION
[0014] The present invention is described with reference to a drilling
assembly,
although many of the methods of the present invention are also applicable with
logging tools conveyed on a wireline and may also be used in cased boreholes.
Figure 1 shows a schematic diagram of an exemplary drilling system 10 such as
that disclosed by Estes. The drilling system has a bottom hole assembly (BHA)
or drilling assembly 90 that includes gyroscope. For some of the applications
of
the present invention, a gyroscope is not essential. The BHA 90 is conveyed in
a borehole 26. The drilling system 10 includes a conventional derrick 11
erected on a floor 12 which supports a rotary table 14 that is rotated by a
prime
mover such as an electric motor (not shown) at a desired rotational speed. The
drill string 20 includes a tubing (drill pipe or coiled-tubing) 22 extending
downward from the surface into the borehole 26. A drill bit 50, attached to
the
drill string 20 end, disintegrates the geological formations when it is
rotated to
drill the borehole 26. The drill string 20 is coupled to a drawworks 30 via a
kelly joint 21, swivel 28 and line 29 through a pulley (not shown). Drawworks
is operated to control the weight on bit ("WOB"), which is an important
parameter that affects the rate of penetration ("ROP"). A tubing injector 14a
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and a reel (not shown) are used as instead of the rotary table 14 to inject
the
BHA into the wellbore when a coiled-tubing is used as the conveying member
22. The operations of the drawworks 30 and the tubing injector 14a are known
in the art and are thus not described in detail herein.
[0015] During drilling, a suitable drilling fluid 31 from a mud pit (source)
32 is
circulated under pressure through the drill string 20 by a mud pump 34. The
drilling fluid passes from the mud pump 34 into the drill string 20 via a
desurger
36 and the fluid line 38. The drilling fluid 31 discharges at the borehole
bottom
51 through openings in the drill bit 50. The drilling fluid 31 circulates
uphole
though the annular space 27 between the drill string 20 and the borehole 26
and
returns to the mud pit 32 via a return line 35 and drill cutting screen 85
that
removes the drill cuttings 86 from the returning drilling fluid 31b. A sensor
Sl
in line 38 provides information about the fluid flow rate. A surface torque
sensor S2 and a sensor S3 associated with the drill string 20 respectively
provide
information about the torque and the rotational speed of the drill string 20.
Tubing injection speed is determined from the sensor S5, while the sensor S6
provides the hook load of the drill string 20.
[0016] In some applications the drill bit 50 is rotated by only rotating the
drill
pipe 22. However, in many other applications, a downhole motor 55 (mud
motor) is disposed in the drilling assembly 90 to rotate the drill bit 50 and
the
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drill pipe 22 is rotated usually to supplement the rotational power, if
required,
and to effect changes in the drilling direction. In either case, the ROP for a
given BHA largely depends on the WOB or the thrust force on the drill bit 50
and its rotational speed.
[0017] The mud motor 55 is coupled to the drill bit 50 via a drive disposed in
a
bearing assembly 57. The mud motor 55 rotates the drill bit 50 when the
drilling fluid 31 passes through the mud motor 55 under pressure. The bearing
assembly 57 supports the radial and axial forces of the drill bit 50, the
downthrust of the mud motor 55 and the reactive upward loading from the
applied weight on bit. A lower stabilizer 58a coupled to the bearing assembly
57 acts as a centralizer for the lowermost portion of the drill string 20.
[0018] A surface control unit or processor 40 receives signals from the
downhole sensors and devices via a sensor 43 placed in the fluid line 38 and
signals from sensors Sl-S6 and other sensors used in the system 10 and
processes such signals according to programmed instructions provided to the
surface control unit 40. The surface control unit 40 displays desired drilling
parameters and other information on a display/monitor 42 that is utilized by
an
operator to control the drilling operations. The surface control unit 40
contains
a computer, memory for storing data, recorder for recording data and other
peripherals. The surface control unit 40 also includes a simulation model and
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processes data according to programmed instructions. The control unit 40 is
preferably adapted to activate alarms 44 when certain unsafe or undesirable
operating conditions occur.
[0019] The BHA may also contain formation evaluation sensors or devices for
determining resistivity, density and porosity of the formations surrounding
the
BHA. A gamma ray device for measuring the gamma ray intensity and other
nuclear and non-nuclear devices used as measurement-while-drilling devices are
suitably included in the BHA 90. As an example, FIG. 1 shows a resistivity
measuring device 64. It provides signals from which resistivity of the
formation
near or in front of the drill bit 50 is determined. The resistivity device 64
has
transmitting antennae 66a and 66b spaced from the receiving antennae 68a and
68b. In operation, the transmitted electromagnetic waves are perturbed as they
propagate through the formation surrounding the resistivity device 64. The
receiving antennae 68a and 68b detect the perturbed waves. Formation
resistivity is derived from the phase and amplitude of the detected signals.
The
detected signals are processed by a downhole computer 70 to determine the
resistivity and dielectric values.
[0020] An inclinometer 74 and a gamma ray device 76 are suitably placed along
the resistivity measuring device 64 for respectively determining the
inclination
of the portion of the drill string near the drill bit 50 and the formation
gamma
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ray intensity. Any suitable inclinometer and gamma ray device, however, may
be utilized for the purposes of this invention. In addition, position sensors,
such
as accelerometers, magnetometers or gyroscopic devices may be disposed in the
BHA to determine the drill string azimuth, true coordinates and direction in
the
wellbore 26. Such devices are known in the art and are not described in detail
herein.
[0021] In the above-described configuration, the mud motor 55 transfers power
to the drill bit 50 via one or more hollow shafts that run through the
resistivity
measuring device 64. The hollow shaft enables the drilling fluid to pass from
the mud motor 55 to the drill bit 50. In an alternate embodiment of the drill
string 20, the mud motor 55 may be coupled below resistivity measuring device
64 or at any other suitable place. The above described resistivity device,
gamma ray device and the inclinometer are preferably placed in a common
housing that may be coupled to the motor. The devices for measuring formation
parameters such as porosity, permeability, resistivity and density
(collectively
designated by numeral 78) are preferably placed above the mud motor 55. Such
devices are known in the art and are thus not described in any detail.
[0022] As noted earlier, a large portion of the current drilling systems,
especially for drilling highly deviated and horizontal wellbores, utilize
coiled-
tubing for conveying the drilling assembly downhole. In such application a
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thruster 71 is deployed in the drill string 90 to provide the required force
on the
drill bit. For the purpose of this invention, the term weight on bit is used
to
denote the force on the bit applied to the drill bit during the drilling
operation,
whether applied by adjusting the weight of the drill string or by thrusters.
Also,
when coiled-tubing is utilized the tubing is not rotated by a rotary table,
instead
it is injected into the wellbore by a suitable injector 14a while the downhole
motor 55 rotates the drill bit 50.
[0023] A number of sensors are also placed in the various individual devices
in
the drilling assembly. For example, a variety of sensors are placed in the mud
motor power section, bearing assembly, drill shaft, tubing and drill bit to
determine the condition of such elements during drilling and to determine the
borehole parameters. The preferred manner of deploying certain sensors in
drill
string 90 will now be described. The actual BHA utilized for a particular
application may contain some or all of the above described sensors. For the
purpose of this invention any such BHA could contain one or more gyroscopes
and a set of accelerometers (collectively represented herein by numeral 88) at
a
suitable location in the BHA 90. A preferred configuration of such sensors is
shown in Figure 2a.
[0024] Figure 2 is a schematic diagram showing an orientation sensor section
200 containing a gyroscope 202 and a set of three accelerometers 204x, 204y
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and 204z disposed at a suitable location in the bottomhole assembly (90 in
Fig.
1) according to one embodiment of the present invention. The gyroscopes 202
may be a single axis gyroscope or a two-axis gyroscope. In vertical and low
inclination wellbores, an x-axis and ay-axis gyroscope are deemed sufficient
for
determining the azimuth and toolface with respect to the true north. The
configuration shown in Figure 2 utilizes a single two-axis (x-axis and y-axis)
gyroscope that provides outputs corresponding to the earth's rate of rotation
in
the two axis perpendicular to the borehole axis or the bottomhole assembly
longitudinal axis, referred to herein as the z-axis. The sensor 202 thus
measures
the earth's rotation component in the x-axis and y-axis. The accelerometers
204x, 204y and 204z measure the earth's gravity components respectively along
the x, y, and z axes of the bottomhole assembly 90.
[0025] The gyroscope 202 and accelerometers 204x-204z are disposed in a
rotating chassis 210 that rotates about the radial bearings 212a-212b in a
fixed
or non-rotating housing 214. An indexing drive motor 216 coupled to the
rotating chassis 210 via a shaft 218 can rotate the chassis 210 in the
bottomhole
assembly 90 about the z-axis, thus rotating the gyroscopes 202 from one
mechanical position to another position by any desired rotational angle. A
stepper motor is preferred as the indexing drive motor 216 because stepper
motors are precision devices and provide positive feedback about the amount of
rotation. Any other mechanism, whether electrically-operated, hydraulically-
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operated or by any other desired manner, may be utilized to rotate the
gyroscopes within the bottomhole assembly 90. The gyroscope 202 may be
rotated from an initial arbitrary position to a mechanical stop (not shown) in
the
tool or between two mechanical stops or from an initial peak measurement to a
second position as described later. The rotational angle corresponding to a
particular axis is selectable.
[0026] Although Figure 2 shows a single two axis gyroscope, a separate
gyroscope may be utilized for each axis. A wiring harness 226 provides power
to the gyroscope 202 and accelerometers 204x, 204y, 204z. The wiring harness
226 transmits signals from the gyroscope and accelerometers to the processor
in
the bottomhole assembly 90. Similarly, a suitable wiring harness 220 provides
power and signal linkage to the stepper motor 216 and additional downhole
equipment. A spring loaded torque limiter 240 may be used to prevent inertial
loading caused by drillstring rotation from damaging the gearbox of the
stepper
motor 216.
[0027] In addition a second two-axis (x-axis and z-axis) gyroscope 230 may be
rotatably mounted in the bottomhole assembly 90 in a rotating chassis or in
any
other manner to measure the rate of rotation in the z-axis and the x-axis, as
shown in Figure 2b. The sensor 230 could be rotated about the y-axis using a
bevel gear 242 and a shaft linkage 244 to the rotating chassis 210, thus
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eliminating the need for an additional motor. The wiring harness 244 for the y-
axis gyro 230 must be spooled around the gyro to accommodate the space
available in a small diameter housing.
[0028] The present invention is first described with reference to a nuclear
sensor. Turning now to Fig. 3, details of a gamma ray sensor that is part of
the
sensor assembly 78 mentioned above are shown. A preferred gamma ray
logging device comprising two gamma ray sensors 252a, 252b is shown along
with an orientation sensor assembly 250. The orientation sensor assembly may
include all the elements of the gyro-MWD device described above, but the some
aspects of the method of the present invention may also be practiced with only
orientation sensors such as accelerometers and or magnetometers. Fig. 3 also
shows a processor 251 associated with the orientation/navigation sensor
assembly. In a preferred embodiment of the invention, the primary purpose of
the processor 251 is to process signals from the orientation/navigation sensor
assembly 250. Also shown in Fig. 3 is a processor 254 associated with the
gamnia ray sensors. It should also be noted that for certain uses of the
method
of the present invention, only one gamma ray sensor may be sufficient.
[0029] In a preferred embodiment of the invention, two gamma ray detectors
spaced 1800 apart are used. When two detectors are used, the counts from the
two may be combined. In a preferred embodiment of the invention, the
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processors 251 and 254 operate at an update frequency of approximately 60Hz.
The counts from the gamma ray sensor(s) are accumulated at a sample rate of
16.67 ms. This is done regardless of the actual rotation speed of the
assembly.
Other sample rates may be used, but a requirement is that it be fixed.
[0030] The "tick" size is defined as the change in the toolface angle over one
time sample interval. The tick size increases with rotation speed and limits
the
resolution of the method and apparatus of the present invention. However, as
discussed below, the effect of tick size can be substantially eliminated.
[0031] In a preferred embodiment of the invention, each detector has an
intrinsic resolution of V 35 . This is determined by the shielding that is
provided for the gamma ray detectors. In the method of the present invention,
the data are binned into finite bins with a defmed angular size, preferably 45
.
The finite bin size further limits the angular resolution. Increasing the
number
of bins improves the angular resolution up to a point beyond which the poor
statistics of gamma ray counts degrade the measurements.
[0032] An important feature of the apparatus of the present invention is a
common bus, designated generally as 260. The various processors (251 and 254
in Fig. 3) output their processed data to the bus. The bus is also connected
to a
telemetry device (not shown) at a suitable location for two-way communication.
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In aui alternate embodiment of the present invention, two-way communication
between the
bottom hole assembly and the surface controller may be accomplished using
flowable
devices carried by the drilling fluid. Such flowable devices are taught in U.
S. Patent
6,443, 228 of Aronstain et al, having the same assignee as the present
application.
(0033] 'I"he advantage of having a common bus 260 is that the processor 251
can process
data from the orientation/navigation sensor independently of the processing of
data from
the gamma ray sensor(s) 252a, 252b by the processor 254. As would be known to
those
versed in the art, it is not unconimon for the rotation speed to be non-
ufiifornl. The
processor 251 continues to process the data from the orientation sensor and
outputs the
toolface angle as a function of time to the bus 260. An advantage of having
the common
bus is that any additional directional evaluation devices could also operate
independently
of the orientation/navigation sensor assembly. As a result of this independent
operation, a
plot of the toolface angle as a function of sample number such as that shown
in Fig. 4 inay
be obtained. The manner in which this is obtained is discussed next.
(0034] Turning now to Fig. 5, eight sectors of tool face angles are shoNvii,
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numbered 0, 1, 2, 3, 4, 5, 6 and 7. The use of eight sectors is optional and
more
or fewer sectors may be used. Also shown are ticks labeled as 301a, 301b, 301c
.. 301n. As noted above, the particular positions of the ticks are not known
at
the time the gamma ray sensor is making measurements- these are determined
after the fact using information from the orientation sensors. The provide
values of the toolface angle at discrete times. The toolface angle at
intermediate
times may be determined by interpolation; in a preferred embodiment of the
invention, linear interpolation is used.
[0035] There are a number of factors that limit the resolution of the method
of
the present invention in terms of tool face angle. The first limit is
determined
by the static resolution of the gamma ray sensors. The static resolution is
the
ability to resolve two point sources of gamma rays and is defined as the
resolution that is achievable with an infinitely long acquisition time (i.e.,
so that
statistical fluctuations are eliminated). Fig. 6 shows an example of a tool
response function as a function of toolface angle. Typically, it is a Gaussian
function with a half-width determined by the shielding provided for the
detectors.
[0036] The actual resolution is obtained by convolving the static resolution
with
a bin window and the tick window; the actual resolution is thus poorer than
the
static resolution. Increasing the number of bins while maintaining the
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acquisition time Ts,q constant does not increase the overall resolution due to
the
fact that the statistical fluctuations within a bin become larger.
[0037] Turning now to Fig. 7, an example of the use of the method of the
present invention is shown. Shown is the apparatus of the present invention
401
including at least one gamma ray detector with region of sensitivity in the
"up"
and "down" direction shown by 409, 411. For simplifying the illustration, in
Fig. 7 it is assumed that the normal to the boundary 403 between formations
405 and 4071ies in a vertical plane so that "up" and "down" directions in Fig.
7
correspond to a combination of sectors (0,7) and (3,4) in Fig. 5 respectively.
The at least one gamma ray detector could comprise a pair of detectors. The
data received by the at least one detector can then be processed to get gamma
ray counts in the "up" and "down" directions respectively. When only one
detector is use, then the combination of measurements from, say sectors 0 and
7
(see Fig. 5) is an "up" measurement while the measurements from sectors 3 and
4 give a "down" measurement. When two detectors are used, their respective
measurements in the "up" and "down" directions may be combined to improve
the signal to noise ratio.
[0038] The apparatus is shown crossing the bed boundary 403 between two
earth formations 405, 407. For illustrative purposes, assume that formation
405
comprises a shale while 407 comprises a sand. For the configuration shown, the
23
CA 02500382 2007-07-16
"up" gamma ray count will be greater than the "down" gamma ray count. The
increased
count is due to the fact that the gamma ray sensors have a limited azimuthal
sensitivity and
the potassilnl present in the shale is a significant source of gamma rays.
100391 By measuring both the "up" and "down" gamtna ray counts as a function
of depth,
a plot shown in Fig. 8 results. Shown are the measurements made by the "up"
and "down"
gamma ray sensors. The abscissa is the borehole depth (actual depth, not true
vertical
depth) and the ordinate is the gamma ray count. In an optional enibodiment of
the
invention, the rate of penetration (ROP) of the assembly in the borehole is
determined
using signals from the axial component accelerometer. Such a method is
disclosed in U.S.
I'atent 6,769,497. Another method of depth determination is disclosed in U. S.
Patent
5,896, 939 to 6ti'ilte et al., having the same assignee as the present
invention, uses a
c.omputer housed in the drilling tool and pre-progranlmed with the data of the
planned
pattern of the borehole. Changes in the drilling mud pressure or flow of the
drilling mud
are detected by a downhole sensor and are used as a counter for the number of
drilling
string segments used. This, together with the known length of a drilling
string segment,
enables the computer to calculate the depth of the BHA. However,
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any suitable method for determining the ROP may be used.
[0040] The horizontal separation between the two curves is an indication of
the
relative angle at which the borehole crosses the bed boundary: the larger the
separation, the smaller the angle. Using knowledge of the tool response
function, this angle can be determined.
[0041] In general, however, bed boundary may have an arbitrary orientation and
the maximum gamma ray count need not correspond to the "up" direction of the
tool (sectors 0,7 in Fig. 5). The gamma ray count O in a deviated borehole as
a
function of the toolface angle N can be approximated by the function
M
'I'M ~ N7,wCOim(o-oo)] (1)
> =o
Such a function satisfies two requirements of the gamma ray count: it must be
a
periodic function with a period of 360 , and it must be symmetric with respect
to the angle No which is the toolface angle at which the detector is closest
to a
bed boundary. Note that the example of Figs. 7 and 8 is a special case when
the
normal to the bed boundary is in a vertical plane. It should also be noted
that
proximity to a bed boundary is not the only cause that will produce a
variation
of the form given by eq. (1); a similar results follows from a radial fracture
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extending out from the borehole.
[0042] To reconstruct the distribution with M terms, it is necessary to have
the
number of bins of data Nbl,,s > 2(M-1)+ 1. Hence to determine a three term
expansion in eq. (1), at least 5 bins are necessary.
[0043] Turning next to Fig. 9, the method of the present invention is
illustrated
by the flow chart. Starting at 501, a model with M=0 is defmed, i.e., there is
no
variation with toolface angle of the gamma ray count. This corresponds to a
model in which
LI'= Const= Wo (2)
A check is made to see if, based on the number of data points, the
observations
can be adequately described by a constant 505 to within a defined probability.
If the answer is "yes", then the process terminates and there is no variation
with
toolface angle of the data.
[0044] If the answer at 505 is "No", then M is incremented 507 and a two term
expansion is made. This requires determination of the angle No. A first
estimate of the angle No is obtained as the average of the data
26
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Nbtns (3).
LJ k Ok
_ k=1
oo - n'arõ.
Y'n k
k=1
The data are then rotated about the angle estimated from eq. (3) and a two
term
fit is made to obtain Oo and Ol according to eq. (1). Keeping these determined
values of 00 and Ol, a new estimate of No is made. A check is again made of
the goodness of fit 505 and again, if the fit is good enough. the process
terminates 509 and if the fit is not good enough, an additional term is added
to
the curve fitting.
[0045] In order to improve the statistics on the measurements, averaging of
the
measurements over a depth window may also be used. As noted above, the
method of Dubinsky discloses a method of using an axial accelerometer for
determining the depth of the tool In the present invention, the method of
Dubinsky is preferred for determining the depth of the assembly and defining
the depth window over which averaging may be done, although other methods
for depth determination may be used.
[0046] In most situations, gamma ray data will not have the necessary
resolution to use the higher order terms of the expansion given by eq. (1).
Hence in a preferred embodiment of the invention, only a single term of the
27
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expansion given by eq. (1) is used. The method illustrated in Fig. 9 may be
used for processing of image data. This is illustrated in Figs. 10a, 10b.
[0047] Shown in Fig l0a are raw data acquired downhole. The vertical axis
represents time (or depth) and the horizontal axis shows the sectors. In this
particular example, eight sectors were used. The display may be a color
display
or may be a black and white display of the gamma ray counts as a function of
time (or depth) and the azimuth (sector). Following the curve fitting (using
the
cosine distributions as discussed above) of the data at a selected time (or
depth),
partially processed data (and a partially processed image), not shown, may be
obtained. The partially processed data are than low pass filtered in the
vertical
direction (time or depth). The filtered image may be quantized into different
levels and the resulting image displayed on a color display or a gray scale.
This
may be referred to as a processed image. An example of this is shown in Fig.
lOb. Also shown in Fig.10b are contours such as 601a, 601b, 601c ... 601n.
In a display such as Fig. lOb, these contours represent dipping boundaries
that
intersect the borehole at an angle.
[0048] Turning now to Fig. 11, a block diagram of equipment used for
determination of density by azimuthal sectors is shown. The microprocessor
used for controlling density measurements is denoted by 709 while the
microprocessor used for azimuth and stand off measurements is indicated by
28
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714. The density measuring device 708 includes a source of nuclear radiation,
two detectors denoted by 705 and 706, and the detectors power supply 704. The
detectors 705 and 706 are called the LS and SS detectors (for long spaced and
short spaced). A preamplifier for the output of the LS and SS detectors is
denoted by 707. Also shown is a common system bus 701, and a modem 703.
It should be noted that additional detectors could also be used. Operation of
the
density measuring device is known in the art and is not discussed further. For
the purposes of the present invention, counts made by the LS and SS detectors
are accumulated by azimuthal sectors while the MWD tool is rotating.
[0049] The standoff/azimuth determination assembly includes two stand off
sensors 711 and 713 and a magnetometer 712. The spatial configuration of the
standoff sensors and magnetometers is shown in Fig. 12.
[0050] Fig. 13 shows idealized magnetometer measurements 751, 753 that
would be made by two magnetometers (referred to as x- and y-) magnetometers.
These may be referred to as the Bx and By measurements. In a vertical
borehole,
the two magnetometer output should be a sinusoid. The magnetometers make
measurements of a magnetic toolface angle that is responsive to the component
of the earth's magnetic field along the sensitive axis of the magnetometer. In
a
deviated borehole, using known relations, the magnetic toolface angle can be
converted to a high side toolface angle indicative of rotation of the tool
about a
29
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longitudinal axis.
[0051] Turning now to Fig. 14, an example of data recorded using density
sensors on a rotating drillstring are shown. Processed data from eight
azimuthal
sectors, each 450 in size, are shown. Measurements made by nuclear sensors are
statistical in the sense that they are dependent upon nuclear interactions
such as
scattering that can be described only in a statistical sense. For the data in
Fig.
14, the source was in sector 7. The curve 801 gives the measured counts
averaged over a number of rotations of the drillstring when the drillstring
was
rotating at 20 rpm. As can be seen, the measured count peaks at sector 7 (as
it
should) and the spread in the count is a measure of the resolution of the
tool.
When the rotation speed is increased to 125 rpm, the results are denoted by
803
and show that the peak count is not in sector 7 (as it should be) but occurs
in
sector 6. When the rotation speed is increased to 200 rpm, the peak count for
the curve 805 is displaced closer towards sector 5. One cause of these
erroneous measurements is a time delay in the electronics. In addition to the
shift in the sector, it can be seen that the absolute counts are also quite
different
with the higher rotational speeds. This can give an erroneous interpretation
of
the magnitude of possible azimuthal variations of formation property.
[0052] Turning now to Fig. 15, shown is a simulated error 851 as a function of
rotational speed of a uniformly rotating tool for a fixed time delay between
the
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time azimuth measurements are made and the time at which they are matched
up with a processor that processes the output of the nuclear sensors. This
explains to a large part the shift in the peak values shown in Fig. 14. The
spread
in the measurements is, on the other hand, due to the statistical nature of
the
nuclear measurements. The abscissa is the rotation speed in rpm while the
ordinate is the error in degrees. At 200 rpm, the error can be over 450 (or
one
sector). It should be noted that similar shifts would be observed with any
kind
of downhole azimuthal sensor measurements, such as resistivity measurements,
nuclear magnetic resonance measurements, natural gamma measurements, etc.
However, the other measurements would not show the statistically caused
spread in the measurements observed with nuclear measurements.
[0053] In reality, the rotational speed may not be uniform. The cause for non-
uniform rotational speed are numerous, and includes the phenomenon known as
stick-slip, wherein the drillbit sticks, and then resumes rotation
intermittently.
An example of what could be observed is shown in Figs. 16a and 16b. Shown
in Fig. 16a are simulated outputs from x- and y- magnetometers. The abscissa
is the rotational angle in tens of degrees and the ordinate is a magnetometer
output. Fig. 16b shows error 905 in degrees for one of the sensors. There are
numerous sources of error that are included.
[0054] One source of error is the non-uniform rotation of the sensor assembly.
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Another source of error is a bias in the magnetometer readings. The bias could
be caused by the drill collar, eddy currents, magnetically permeable metal in
the
vicinity of the magnetometers. In the present invention, the errors are
removed
by using a methodology outlined in Fig.17. A check is made of the
magnetometer outputs to verify that rotation is occurring 1001. Rotation can
be
confirmed by several techniques previously known in the art, including
counting zero-crossings, counting peaks, computing an FFT and determining a
fundamental frequency of a minimum amplitude in an expected range, or fitting
a sinusoid to the sampled data within certain bounds. The outputs are
accumulated over an appropriate period of time (or number of cycles or
rotation
and the average value is determined 1003. This is done separately for the Bx
and By measurements and gives a bias value that is then subtracted 1005 from
the magnetometer measurements. A scale factor is then determined relating the
magnitudes of the sinusoids for the Bx and By components 1007. This is based
on the assumption that the Bx and By measurements are exposed to the same
external field and that they are primarily seeing the component of the earth's
magnetic field in the radial direction (perpendicular to the tool axis). A
check is
made to make sure that the adjustments are within acceptable tolerances for
changes and the rate of change. In open hole (with no local magnetic
gradient),
the compensated magnetometer should produce sinusoidal outputs while
rotating at constant speed. A check of this condition can include fitting a
sinusoid to the X and Y readings, respectively, and verifying sufficiently
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adequacy of the fit. If the presence of a significant gradient is indicated,
the
bias compensation routine can be delayed until drilling advances the sensor to
a
"clean" section of the wellbore.
[0055] A shift in the determined angle based on a nominal rotational speed
(see
Fig. 15) is then applied to the bias-corrected, scaled Bx and By measurements.
Correcting both the bias and scale factor is required to avoid distortion of
the
derived toolface angle. The magnetic toolface angle is determined
bytari 1(BylBx).
[0056] Turning now to Fig. 18, a plot is shown of counts by sector after
applying the corrections. Comparing with Fig. 14, it can be seen that the
curves
803' and 805' do not show an azimuthal shift relative to the curve 801' (the
lowest rotational speed). It is also seen that the magnitudes of the curves
are
higher speed are not much different from the magnitude at lower speed. This
will give a better azimuthal image than would be obtained by data
corresponding to Fig. 4.
[0057] The improvement in imaging capabilities also applies to other formation
evaluation sensors. For example, prior art methods use resistivity sensors for
obtaining a resistivity image of the borehole wall. Bedding of the earth
33
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formation is commonly indicated by resistivity contrasts, so that by fitting
sinusoids to the resistivity image, an apparent dip (and strike direction) of
the
bedding to the borehole axis can be obtained. Absolute dip and strike can then
be inferred from survey information. In the presence of non-uniform rotation,
the sinusoidal curve fitting can be a problem. With the method of the present
invention, compensation is made for errors in the toolface angle, resulting in
improved determination of bedding.
[0058] Another feature of the present invention is the selection of the low-
pass
filter used for the A/D converter for the magnetometer data. The angular error
curve shown in Fig. 6b had a 50Hz low pass filter applied to the magnetometer
data. This is believed to be too restrictive. Shown in Fig. 9 is the angular
error
curve of the magnetometer data after applying the process discussed with
respect to Fig. 7 and with a 250Hz low pass filter for the A/D converter. The
magnitude of the error is typically less than 10 compared to values as large
as 6
in Fig. 7.
[0059] The method of the present invention has been discussed above with
respect to a gamma ray logging tool. However, the method of the present
invention may also be used with any kind of logging tool having a sensitivity
that is dependent upon the toolface angle. Fig. 20 illustrates the arrangement
of
a plurality of resistivity sensors on a single pad 1051. Such a configuration
is
34
CA 02500382 2007-07-16
discussed in US I'atent 6,173, 794 to Ihonlpson et al. The electrodes are
arranged in a
plurality of rows and columns: in Fig. 20, two columns and three rows are
shown, witll the
electrodes identified as 1053a, 1053b, 1055a, 1055b, 1057a and 1057b. Having a
plurality of coluinns increases the azimuthal resolution of resistivity
measurements while
having a phirality of rows increases the vertical resolution of resistivity
measurements.
Resisitivity measurements are different from nuclear measurements in that
there is little or
no statistical variation in the measurements. Consequently, the measurements
are made
substantially iiistantaneously and thus have a higher resolution in azimuthal
angle than
nuclear measurements.
[0060) A variety of resistivity sensors is disclosed in U. S. Patent
Application Pub. No.
2005/0001624 of Riller et al., having the same assignee as the present
application. Ritter
teaches an apparattis and method of obtaining a resistivity image of'a
borehole during
drilling operations. A resistivity sensor is maintained at a specified
standoff from the
borehole wall. A processor uses measurements from an orientation sensor on the
resistivity sub for determining a toolface orientation during continued
rotation. The
resistivity sensor may be mounted on a pad, rib, or a stabilizer. The
resistivity sensor may
be galvanic and may include suitable focusing, guard and monitor electrodes. A
variety of
f:ocusinb techniques may be used. A processor, pref:erably downhole, may be
used for
rnaintaining a substantially constant power consumption. The orientation
sensors may be
a magnetometer, an accelerometer, or a gyroscope. In oil based mud, capacitive
coupling
may be used. Multifrequency measurements may be used in combination with known
CA 02500382 2007-07-16
fiequency focusing techniques. Ritter also teaches the use of non-galvanic
sensors for
making resistivity measurements.
100611 The method of the present invention may also be used with measurements
made
with resistivity sensors having transverse induction coils <BR> such as that
described in
US Patent 6,147, 496 of Strack et al.
[0062] The method of the present invention may also be used with the apparatus
described
in U. S. Patent 6,957.708 of Cherrmali et al. The apparatus disclosed therein
includes a
rotatable drill collar, and may include at least one extendable stabilizer
joined to the drill
collar, at least one transmitter for injecting at least one RF signal into the
formation, and at
least one receiver for measuring the phase and attenuation of the RF signal
upon
propagation through the formation. The at least one receiver and the
transmitter define a
plurality of transmitter-rec.eiver spacings. A hardfacing enables a specified
standoff of the
stabilizer from the borehole wall. Rate of penetration of the drill collar can
be determined
using for instance, an axial accelerometer, or a second resistivity sensor
placed at a
different axial position.
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A plurality of directional sensors may be used, each of which preferably has
its
own associated processor connected to the common bus.
[0063] As taught by Thompson et al., the method of processing of the acquired
data from any one of these arrangements of formation sensors is discussed with
reference to Figs. 21-22. For illustrative purposes, Fig. 21 illustrates the
"unwrapped" resistivity data that might be recorded by a first resistivity
sensor
rotating in a borehole as the well is being drilled. The abscisa has values
from
0 to 360 corresponding to azimuthal angles from a reference direction
determined by a directional sensor. The vertical axis is the time of
measurement. As the resistivity sensor rotates in the borehole while it is
moved
along with the drill bit, it traces out a spiral path. Indicated in Fig. 21 is
a
sinusoidal band 1131 corresponding to, say, a bed of high resistivity
intersecting
the borehole at a dipping angle.
[0064] In one embodiment of the invention, a downhole processor uses the
depth information from downhole telemetry available to the telemetry device
and optionally sums all the data within a specified depth and azimuth sampling
interval to improve the S/N ratio and to reduce the amount of data to be
stored.
A typical depth sampling interval would be one inch and a typical azimuthal
sampling interval is 15 . Another method of reducing the amount of data stored
would be to discard redundant samples within the depth and azimuth sampling
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interval. Those versed in the art would recognize that a 2-D filtering of the
data
set by known techniques could be carried out prior to the data reduction. The
data after this reduction step is displayed on a depth scale where the
vertical
axis is now depth and the horizontal axis is still the azimuthal angle with
respect
to a reference direction. The dipping resistive bed position is indicated by
the
sinusoid 1101'. Such a depth image can be obtained from a time image if at
times corresponding to measurements such as 1101 and 1103, the absolute
depth of the resistivity sensor were known.
[0065] Those versed in the art would recognize that a apparent dip angle
between the bed boundaries and the borehole axis is readily determinable from
the amplitude of the sinusoid 1101' and the diameter of the borehole. The
apparent dip angle is the angle seen in a borehole when the borehole is an
angle
other than the strike angle of an interface. Given an apparent dip angle,
strike
direction, the borehole inclination and aziniuth, the relative dip angle can
be
determined. The borehole inclination and azimuth are obtained, for example,
from gyro measurements. For the determination of this amplitude, it is not
essential to have exact depth measurements: it is sufficient to know the rate
of
penetration (ROP) during the time period that the sinusoid 1101' is being
measured. A rate of penetration may be obtained using accelerometer
measurements such as that disclosed in U.S. Patent application Ser. No.
10/167,332 of Dubinsky et al., having the same assignee as the present
invention
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and the contents of which are fully incorporated herein by reference. As
disclosed in Dubinsky, one of several methods may be used for determination of
ROP. These include identification of maxima and minima of velocity (obtained
by integration of accelerometer measurements), average acceleration magnitude
and an instantaneous frequency of measurements.
[0066] Alternatively, the ROP may be determined by measurements made with
two axially spaced apart resistivity sensors. This is illustrated in Fig. 21
by a
second resistivity band 1131 corresponding to the same dipping band 1101 as
measured at a second resistivity sensor directly above the first resistivity
sensor.
The spacing between the first and second resistivity sensors being known, a
rate
of penetration is computed by the microprocessor by measuring the time shift
between the bands 1101 and 1131. The time shift between the bands 1101and
1131 could be determined by one of many methods, including cross-correlation
techniques. This knowledge of the rate of penetration serves as a check on the
depth information communicated downhole and, in the absence of the downhole
telemetry data, can be used by itself to calculate the ROP and apparent dip.
This method is particularly useful in highly deviated boreholes, or in any
situation where the apparent dip angle is large, so that a single resistivity
sensor
would not see the entire sinusoid.
[0067] Alternatively a hypothetic apparent dip value may be computed
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downhole for an assumed ROP and sent to the surface by the telemetry device.
The corrected dip value is provided by the surface system by taking into
account the ratio between the assumed ROP value from the downhole processor
and the actual ROP measured at the surface.
[0068] In the method taught by Thompson, the resistivity sensors are on a
sleeve
that is decoupled from the drill collar and is thus rotating quite slowly.
Hence
the problems discussed above with respect to stick slip motion of the drill
string,
non-uniform rates of rotation, and time delays between the time of .
measurements made by the orientation sensor and the resisitivy sensor.
However, non-uniform rotation rate and the time delay would be a problem with
the methods discussed by Ritter and with the methods discussed by Clark et al.
If correction is not made for these effects, the unwrapped image of a
formation
boundary would be hard to interpret. This is illustrated in Fig. 22 in an
exaggerated fashion.
[0069] Shown in Fig. 23 is a sinusoid 1161 corresponding to a bed boundary.
Depicted along the sinusoid are exemplary positions 1151 a, 1153a, 1155a,
1157a and 1159a at which a single sensor crosses the bed boundary. If the rate
of rotation of the drillstring is non-uniform, then in the presence of a time
delay
between between the orientation and resistivity sensors, the sensor appears to
cross the bed boundary at points denoted by 1151b, 1153b, 1155b, 1157b and
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1159b, giving a curve 1163 that is not sinusoidal, so that prior art curve
fitting
techniques to identify the dip of a bed boundary would not work. When the
ROP is small, the effect of the non-uniform rotation is to reduce the
resolution
of the bed boundary.
[0070] In another embodiment of the invention, image correction may be made
and possible stick-slip may be identified. This is schematically illustrated
in
Fig. 24. Shown in Fig. 24 are three interfaces 1201, 1203 and 1205 as they
would appear if no correction is made. The regions 1221 and 1223 correspond
to orientations where there is possible sticking during rotation of the
drillstring.
Applying the method of the present invention, these irregular curves would be
sinusoids. The images are not limited to resistivity measurements-they could
be images obtained by any prior art borehole imaging tool including acoustic
images, density images or porosity images.
[0071] The method of the present invention may be used in reservoir navigation
wherein the objective is to maintain the borehole in a specific relation to a
fluid
interface and/or a caprock. This is schematically illustrated in Figs. 25a and
25b. Shown in Fig. 25a is a vertical section through a reservoir having a
caprock 1251, oil zone 1253 and water zone 1255. The top of the reservoir is
indicated by 1257 while the oil-water contact is indicated by 1259. Also shown
are two exemplary boreholes by 1261 and 1263.
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[0072] Fig. 25b is a simplified plan view of Fig. 25a with the wells denoted
by
1261' and 1263'. Also shown by 1265 is the edge of the oil bearing portion of
the formation-the curved portion of 1265 at the top of Fig. 25b being an
indication that the reservoir is pinching out. Keeping in mind the fact that
resistivity sensors are able to see some distance into the formation,
measurements made in wellbore 1263 will generally be featureless unless the
borehole is getting too close to either the caprock or to the oil-water
contact.
When the borehole approaches either the caprock, some change in resistivity
will be picked up in the top portion of the sinusoid whereas if the borehole
approaches the oil-water contact, some decreased resistivity will show up on
the
bottom portion of the sinusoid. In either case, the image will be symmetrical.
[0073] On the other hand, in wellbore 1261, these same features will appear to
be asymmetrical with respect to the up and down directions due to the pinching
out.of the reservoir. Detection of such features clearly requires an accurate
determination of the toolface angle.
[0074] The method of the present invention may also be used with wireline
logging tools. When used with wireline tools, a motor is needed for rotating
the
assembly through different toolface angles so as to provide adequate sampling
over the circumference of the borehole. The wireline tools may be run open
42
CA 02500382 2005-03-24
WO 2005/017315 PCT/US2004/004694
hole or, in case of certain types of sensors such as gamma ray sensor, in
cased
hole. A slickline sensor assembly may also be used within a drillstring for
some
types of measurements.
[0075] While the foregoing disclosure is directed to specific embodiments of
the invention, various modifications will be apparent to those skilled in the
art.
It is intended that all variations within the scope and spirit of the appended
claims be embraced by the foregoing disclosure.
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